BP Exploration and Production

Sunbury, United Kingdom

BP Exploration and Production

Sunbury, United Kingdom
SEARCH FILTERS
Time filter
Source Type

Seevam P.,BP Exploration and Production | Race J.,Newcastle University | Downie M.,Newcastle University | Barnett J.,UK National Grid Corporation | Cooper R.,UK National Grid Corporation
Proceedings of the Biennial International Pipeline Conference, IPC | Year: 2010

Climate change has been attributed to green house gases, with carbon dioxide (CO2) being the main contributor. Sixty to seventy percent of carbon dioxide emissions originate from fossil fuel power plants. Power companies in the UK, along with oil and gas field operators, are proposing to capture this anthropogenic CO2 and either store it in depleted reservoirs or saline aquifers (carbon capture and storage, CCS), or use it for 'Enhanced Oil Recovery' (EOR) in depleting oil and gas fields. This would involve extensive onshore and offshore pipeline systems. The decline of oil and gas production of reservoirs beyond economic feasibility will require the decommissioning onshore and offshore facilities post-production. This creates a possible opportunity for using existing pipeline infrastructure. Conversions of pipelines from natural gas service to CO2 service for EOR have been done in the United States. However, the differing sources of CO2 and the differing requirements for EOR and CCS play a significant part in allowing the re-use of existing infrastructure. The effect of compositions, the phase of transportation, the original pipeline specifications, and also the pipeline route require major studies prior to allowing re-use. This paper will first review the requirements for specifying the purity of the CO2 for CCS and to highlight the implications that the presence of impurities and the current water specifications for pipelines has on the phase diagram and the associated physical properties of the CO2 stream. A 'best' and 'worst' case impurity specification will be identified. Then an analysis on the impact and subsequent validation, of equations of state based on available experimental data on the phase modelling of anthropogenic CO2 is presented. A case study involving an existing 300km gas pipeline in the National Transmission System (NTS) in the UK is then modelled, to demonstrate the feasibility of using this pipeline to transport anthropogenic CO2. The various issues involved for the selected 'best' and 'worst' case specification are also covered. This is then followed by an investigation of the options for transport in the 'gas' phase and 'supercritical' phases, and also identifying the limitations on re-using pipeline infrastructure for CCS. Copyright © 2010 by ASME.


Harwood J.,Northumbria University | Aplin A.C.,Northumbria University | Aplin A.C.,Durham University | Fialips C.I.,Northumbria University | And 5 more authors.
Journal of Sedimentary Research | Year: 2013

Evaluating the timing and origin of quartz cement is central to understanding how porosity is lost in sandstones during burial. Kinetic models of quartz cementation have been calibrated using large-scale datasets but have never been tested at the microscopic level at which cement forms. Here, we use high-precision, in situ oxygen isotope analyses on sandstone from the Jurassic Ness Formation from the North Sea to reveal the growth history of single quartz overgrowths to a resolution of 2 μm. Measured δ18O (cement) range from +28 to +20% V-SMOW in early to late cement and are consistent with quartz cementation models that propose the bulk of quartz precipitates as a continuous process beginning at 60-70 °C. Quantitative X-ray Diffraction analyses and clay mineralogical analysis of interbedded shales are inconsistent with a silica source from shale, implying that silica for the cement is sourced internally to the sand. These isotope data are broadly consistent with predictive, conceptual quartz cementation models and provide a critical link from micron-scale measurements to basin-scale predictions and observations. Copyright © 2013, SEPM (Society for Sedimentary Geology).


Tozer R.S.J.,BP Exploration and Production | Borthwick A.M.,BP Exploration and Production
Geological Society Special Publication | Year: 2010

The Azeri field in the South Caspian Sea, offshore Azerbaijan, is a periclinal anticline 20 km in length containing multiple stacked reservoirs of Pliocene age. Appraisal wells that were drilled at the eastern end of the structure identified multiple oil-water contacts and fluid pressure gradients in both of the principal reservoirs, the Pereriv B and D. At the time, these data were interpreted to indicate the presence of compartments at the eastern end of the field as a result of sealing faults within the aquifer. This local compartmentalization seemed to be in marked difference to the majority of the field where pressure connectivity had been observed. A new analysis of the pressure data for the Pereriv B shows that aquifer pressures at sea-level datum define a simple water potential gradient. As a result of this, the oil-water contact in this reservoir is gently inclined towards the NNE. The precise inclination and orientation of the oil-water contact has been determined geometrically using the depths and coordinates of free-water levels and oil-water contacts from around the field. The best-fit inclined oil-water contact for the Pereriv B also provides a good fit to the contact observed from seismic amplitudes. The new analysis provides a more optimistic view of reservoir connectivity, and the conceptual geological model for the eastern end of the field is now consistent with observations made in the rest of the Azeri field. © The Geological Society of London 2010.


Muggeridge A.,Imperial College London | Cockin A.,BP Exploration and Production | Webb K.,BP Exploration and Production | Frampton H.,BP Exploration and Production | And 3 more authors.
Philosophical Transactions of the Royal Society A: Mathematical, Physical and Engineering Sciences | Year: 2014

Enhanced oil recovery (EOR) techniques can significantly extend global oil reserves once oil prices are high enough to make these techniques economic. Given a broad consensus that we have entered a period of supply constraints, operators can at last plan on the assumption that the oil price is likely to remain relatively high. This, coupled with the realization that new giant fields are becoming increasingly difficult to find, is creating the conditions for extensive deployment of EOR. This paper provides a comprehensive overview of the nature, status and prospects for EOR technologies. It explains why the average oil recovery factor worldwide is only between 20% and 40%, describes the factors that contribute to these low recoveries and indicates which of those factors EOR techniques can affect. The paper then summarizes the breadth of EOR processes, the history of their application and their current status. It introduces two new EOR technologies that are beginning to be deployed and which look set to enter mainstream application. Examples of existing EOR projects in the mature oil province of the North Sea are discussed. It concludes by summarizing the future opportunities for the development and deployment of EOR. © 2013 The Author(s) Published by the Royal Society. All rights reserved.


Morana R.,BP Exploration and Production | Smith V.C.M.,BP Exploration and Production | Smith A.,Centro Sviluppo Materiali S.p.A
NACE - International Corrosion Conference Series | Year: 2015

The qualification of materials in accordance with NACE MR0175/ISO 15156 is commonly performed by subjecting candidate materials to stress corrosion testing under an applied load in either a standard test solution (e.g. NACE solution A or B) or a test environment simulating service conditions. The exposure times for standard NACE solution A or B can vary from a few days up to a month (720 hours), whilst the exposure time for simulated service conditions is typically one month. This is widely accepted in the Oil & Gas industry and supported by good field experience with alloys such as martensitic and duplex stainless steels, suggesting that this duration is sufficient for those materials. A similar approach has also been employed in the past for precipitation hardening (PH) nickel alloys, which are being increasingly used in the Oil & Gas Industry. However, field failures of some NACE MR0175/ISO 15156 qualified PH nickel alloys have raised questions over the suitability of the exposure times and test methods that were used. The present work focused on PH nickel alloys exposed to the NACE Level VI and VII environmental conditions described in NACE MR0175/ISO 15156 for up to 1 year exposure time, to evaluate their performance using both 'conventional' and 'accelerated' testing techniques. The results indicate that the 'conventional' qualification methodology might not be suitable to ensure continuous safe operation for the materials investigated even with extended testing periods (up to one year). However, the approach used in the present work was not fully reproducible and needs further improvement. © 2015 by Nace International.


Smith V.C.M.,BP Exploration and Production | Hinds G.,National Physical Laboratory United Kingdom | Bishop A.,Exova Corrosion Center | Morana R.,BP Exploration and Production | And 2 more authors.
NACE - International Corrosion Conference Series | Year: 2015

Prior to 2003, hydrogen induced cracking (HIC) testing was not incorporated into NACE MR0175/ISO 15156(1) and generally was not required for mildly sour environments (i.e. Region 0) and thus assets operating in CO2-containing environments with potentially very low levels of H2S were commonly built using 'sweet' steel grades. A consideration of HIC, even for traces of H2S, became mandatory in the 2003 revision, but the associated threat has not been quantified. Very few instances of pipeline leakages due to HIC have however been reported. Recent work carried out by the European Pipeline Research Group(2) suggested that there could be a threshold below which HIC may not be a credible threat. That study, however, used 'modern' linepipe materials and it well known that 'heritage' or vintage materials are inherently more susceptible to HIC, due to a lesser degree of control of inclusions, leading to HIC in rolled materials. Safe operating limits of vintage steels need to be defined to ensure reliable and inherently safe operations. In the present work, four vintage steels have been tested using small and full-scale testing, coupled with non-destructive monitor/inspection. Safe operating limits of heritage materials have been established and the roles played by inclusions on crack initiation, and by banded microstructure on crack propagation, have been clarified. © 2015 by Nace International.


Go J.,Imperial College London | Bortone I.,Imperial College London | Muggeridge A.,Imperial College London | Smalley C.,BP Exploration and Production
Transport in Porous Media | Year: 2014

Sudden changes in isotopic tracer concentration in pore waters have been interpreted as indicating barriers to vertical advective flow through porous rocks in the subsurface, e.g. step changes in 87Sr/86Sr ratio are often used in the oil and gas industry as a signature of reservoir compartmentalisation. This study shows that this is not necessarily the case. It can take millions of years for such step changes to equilibrate by diffusion if there is no flow resulting from pressure or density gradients even in high permeability, high porosity rocks, particularly if the water saturation is low. Changes in tracer concentration gradients can be good indicators of changes in porosity (or water saturation) between layers. In contrast changes in sorption without a change in porosity are almost impossible to identify. The time taken for concentration gradients to equilibrate is affected by the layer properties but can be quickly estimated from the harmonic average of the effective diffusion coefficient for each layer and a simple analytical expression for a homogeneous system. This was achieved by performing a sensitivity analysis on different layer properties (porosity contrast, saturation contrast, sorption contrast, thickness ratio) using existing analytical solutions for diffusion in layered systems. © 2014, Springer Science+Business Media Dordrecht.


Woollam R.,BP Exploration Operating Co. | Tummala K.,BP Exploration and Production | Vera J.,BP Exploration and Production | Hernandez S.,BP Exploration Alaska Inc.
NACE - International Corrosion Conference Series | Year: 2011

Oil and gas production facilities transport a wide range of fluids which may contain carbon dioxide (CO2), hydrogen sulfide (H2S) and many other species that may lead to a corrosive environment. To ensure safe and cost effective production operations it is important to understand the combined effect of H2S and CO2 on corrosion rates and the corrosion products formed in these environments. The formation of iron sulfide (FeS) and iron carbonate (FeCO3) scale under a corrosive environment is one of the important factors governing corrosion rates in CO2 and H2S corrosive systems. This paper presents a simplified thermodynamic model to predict the dominant mineral on the corroding surface exposed to a range of mixed partial pressures CO2 and H2S. The approach is based on thermodynamic estimate of equilibrium constants i.e. Ksp for FeCO3 and Ksp for FeS to account for the formation of iron sulfide and iron carbonate scales at varying temperature, pH, iron concentrations and partial pressure of CO2 and H2S. The application and limitations of this model as a methodology to predict the dominant scale (i.e. iron sulfide or iron carbonate) on the corroding surface is discussed. © 2011 by NACE International.


Dale A.,Imperial College London | John C.M.,Imperial College London | Mozley P.S.,New Mexico Institute of Mining and Technology | Smalley P. C.,BP Exploration and Production | Muggeridge A.H.,Imperial College London
Earth and Planetary Science Letters | Year: 2014

Septarian carbonate concretions contain carbonate precipitated during progressive growth of the concretion and subsequent fracture-filling. As such, they have been used to track variations in δ13C and δ18O of pore waters during diagenesis and to define diagenetic zones in clastic rocks. However, the δ18O value of the carbonate is dependent on precipitation temperature and the δ18O value of the pore fluid from which it precipitated. Interpretations must assume one of these parameters, both of which are highly variable through time in diagenetic settings. Carbonate clumped isotopes of the cement can provide independent estimates of temperature of precipitation, allowing the pore-water δ18O to be back-calculated. Here, we use this technique on carbonate concretions and fracture fills of the Upper Cretaceous Prairie Canyon Member, Mancos Shale, Colorado. We sampled concretions from two permeable horizons separated by a 5 m shale layer, with one permeable horizon containing concretions with septarian fractures. We show cores precipitated at cooler temperatures (31 °C, ~660 m burial depth) than the rims (68 °C (~1980 m burial depth) and relate that to the δ13Ccarbonate values to suggest the concretion core precipitated in the methanogenic zone, with increasing input from thermogenically produced CO2. The two concretion-bearing horizons have different back-calculated δ18Oporewater values (mean -2.65‰ and 1.13‰ VSMOW) for cements formed at the same temperature and similar δ13C values, suggesting the shale layer present between the two horizons acted as a barrier to fluid mixing. Additionally, the δ18Ocarbonate of the septarian fractures (-13.8‰ VPBD) are due to precipitation at high temperatures (102 to 115 °C) from a fluid with a mean δ18Oporewater of 0.32‰ (VSMOW). Therefore, we can tie in the cementation history of the formation to temporal and spatial variations in δ18Oporewater. © 2014 The Authors.


Smedley P.,BP Exploration and Production | O'Connor P.,BP Exploration and Production
Proceedings of the International Conference on Offshore Mechanics and Arctic Engineering - OMAE | Year: 2011

The ISO 19900 series of Standards address the design, construction, transportation, installation, integrity management and assessment of offshore structures. Offshore structural types covered by ISO include: bottom-founded 'fixed' steel structures; fixed concrete structures; floating structures such as monohull FPSOs, semi-submersibles and spar platforms; arctic structures; and site-specific assessment of jack-up platforms. All the fundamental ISO Offshore Structural Standards have now been published representing a major achievement for the Oil and Gas Industry and representative National Standards Organizations. A summary of the background to achieving this milestone is presented in this paper. In parallel, other Codes and Standards bodies such as API, CEN, CSA, Norsok and the Classification Societies are looking to harmonize some, or all, of their Offshore Structures Standards in-line with ISO, wherever this is desirable and practical. API, in particular, have been pro-active in reviewing and revising their Offshore Recommended Practices (RPs) to maximize consistency with ISO, including revising the scope and content of a number of existing API RPs, adopting ISO language, and embracing technical content. Given API's long heritage of Offshore Standards it is not surprising that this remains very much a mutual effort between ISO and API with much in ISO Standards building on existing API design practice. Now published, those involved in developing and maintaining the ISO 19900 series of Standards have to deal with both new and existing challenges, including encouraging wider awareness and adoption of these Standards, enhancing the harmonization effort, ensuring technical advances are captured in timely revisions to these Standards, and most pressing to ensure that the next generation of offshore engineers are encouraged to participate in the long-term development of the Standards that they will be using and questioning. This paper is one of a series of papers at this OMAE Conference that outline the technical content and future strategy of the ISO Offshore Structures Standards. Copyright © 2011 by ASME.

Loading BP Exploration and Production collaborators
Loading BP Exploration and Production collaborators